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Monday, May 8, 2017

Drillers Provide 2017 First Quarter Updates

UPDATE ON 5/8/17

Several more drillers have released reports on their activity.

From Eclipse Resources:

The Company updated its Utica Dry Gas type curve assumptions, resulting in an increase in EUR of approximately 13% to approximately 2.2 Bcf per 1,000 foot of lateral based on the results of extended flow testing on its completed Dry Gas Utica Shale wells using the Company’s “Gen3” completion design, which is expected to generate a before tax internal rate of return of approximately 70% at today’s forward natural gas strip pricing.

The Company successfully drilled its newest record setting “Super-Lateral” well, the Great Scott 3H, with a total measured depth of 27,400 feet and completable lateral extension of 19,300 feet in less than 17 days from spud to TD in the Company’s Utica Shale Condensate area.

The Company completed drilling its first of two planned Marcellus Shale Condensate wells with a completable lateral extension of 10,000 feet.

The Company issued second quarter 2017 production and expense guidance and updated its full year production and expense guidance, resulting in an increase in its expected average daily production guidance range for 2017 to between 315 and 320 MMcfe per day and a reduction in its 2017 per unit operating expenses for 2017 to between $1.40 and $1.50 per Mcfe.

So I guess what I'm really asking is, as you evolve the portfolio towards these more oily areas, higher-rate areas, more economic areas, how do you think about the relative reset in your portfolio? I'm thinking specifically Marcellus and whether you would ever consider accelerating asset sales across some of your more pure-play gas positions?

Robert Douglas Lawler - Chesapeake Energy Corp.

Sure. Well, it's a great question, Doug. And as we evaluate the portfolio constantly, the churn in evaluation consists of what is the EBITDA generation, what is the future potential, what is the competitive investment thesis in our portfolio of great assets going forward. But the key in my mind and across the company is that we're going to continue to improve our operations and continue to improve our balance sheet and look for opportunities to reduce our debt further as quickly as possible.

I'd just draw your attention back to what the investment community's view of the Haynesville was a few years ago, and the significant value that our operating expertise and experience, what that's done and the uplift there that we've recognized and the value of that asset in the past few years as we continue to drill and produce just big boomer wells there in the Haynesville Shale. That same transfer of technology and operating capability we've pushed to the Powder River. And we have that excitement there.

And as you look at the Marcellus and the Utica in the Northeast, these are very, very strong cash-generating assets. Some of the best rock shale, gas rock in the world. When you can spend $100 million and keep an asset flat at 2 BCF a day for next five-plus years, it's a tremendous asset to have in our portfolio. What I'm getting at there is that, if we can accelerate the value, we will absolutely do that and consider bigger asset sales, broader asset sales, to accelerate the value to our shareholders.

But make no mistake, along the way as we evaluate the portfolio and continue with our investment thesis, we are driving the greatest value in a very disciplined capital program, pursuing that free cash flow neutrality. Essentially, if it weren't for some of the extraneous items the past several quarters, our spending has been in line, capital spending for drilling and completion, CapEx within our EBITDA. And we're going to continue those asset sales and look for opportunities to add the value. But make no mistake, across the portfolio, we're making meaningful improvements that will generate value for our shareholders in the future.

In Belmont County, we turned to sales 10 net operated Utica wells with an average lateral length of 8,400 feet. Our average lateral length for Utica wells drilled and completed during the quarter was 10,600 feet and development cost averaged $1,130 per foot.

Our Utica development costs were 9% below budget resulting from improved operating efficiencies and lower-than-expected service cost inflation. Of note, during the first quarter, we drilled a five-well pad with an average of 12,700 foot laterals at an average drilling cost 30% below budget.

We're incredibly proud of our team's accomplishments this quarter. We recently set the Utica industry's recorded by drilling 6,170 feet in a 24-hour period of time. The team continues to be technical leaders as evidenced by holding the industry record for drilling in the Utica.

Several drillers have reported on their first quarter activity this year. View some of the details from these various releases below.

From EQT:

Finally, an update on our Utica program. As we've indicated during previous calls, we continue to work in understanding the reservoir and improving costs and have decided to not share individual well results as we move along. We have completed the Big 177 well in Wetzel County, West Virginia, and it is online. Our 2017 plan calls for drilling seven wells and we are currently drilling the Moore well in Greene County, PA, and should have that well online in the second quarter. After we TD the Moore, we will move the rig to Armstrong County, Pennsylvania to drill the next Utica well. With these test wells, we are getting a better understanding of the production mechanisms, recoveries, and the economics of Utica, which was our overall goal of the 2017 program.

Rex Energy's first quarter 2017 production was 173.4 MMcfe/d, consisting of 110.1 MMcf/d of natural gas, 9.7 Mboe/d of NGLs (including 5.0 Mboe/d of ethane) and 0.8 Mboe/d of condensate. Condensate and NGLs (including ethane) accounted for 36% of production during the quarter.

During the first quarter of 2017, realized natural gas prices, before the effects of hedging, improved approximately 42% as compared to fourth quarter 2016 realized natural gas prices. The improvement in natural gas realizations was driven by improved differentials in the northeast markets and a full quarter of the company's Gulf Coast transport. In addition, C3+ NGL prices, before the effects of hedging, average approximately 59% of WTI oil prices. The improvement in C3+ NGL prices was largely due to continued improvement in Mont Belvieu prices and improved differentials for C3+ NGLs in the northeast. The company continues to expect full-year 2017 realized C3+ NGL prices to average approximately 50% - 55% of WTI.

"Our first quarter result 2017 results are the first step in achieving our two-year plan for 2017 and 2018," commented Tom Stabley, President and CEO of Rex Energy. "One of the most important highlights of the quarter was our price realizations, with the strong results underlining the importance of our marketing initiatives and current marketing portfolio. With a full year of Gulf Coast transport and improved differentials in the northeast markets, we expect to see improved realizations throughout the year and will continue to pursue further enhancements to our marketing portfolio to further improve our realizations."

Moving to Southwest Appalachia, we're continuing our early testing that was accelerated from 2018 on our first Utica well, the OE Burge. This well is currently flowing at a flat rate of 17 million cubic feet per day, with over 8,500 PSI of pressure. Based on our current assumptions, early results indicate this well is a top quartile well in the region, with an average EUR of 2.5 to 3 BCF per one thousand feet of lateral. This type of productivity shows the potential of the enormous resource this play and our estimated 1,400 locations.

Also, we recently placed five wells online that tested tighter stage phasing and increased profit loading. Four of these wells were completed utilizing 140 foot stage phasing and 3,500 pounds of profit per foot, while one additional well was completed utilizing as much as 5,000 pounds per foot of profit. Early indications shows that all five of these wells are performing better than their closest offsets. And to date, these five test wells have performed similarly and we will continue to monitor these wells to determine their long term performance enhancements.

As a quick update on the Utica, I believe it's worth pointing out the updated map in our presentation on page 44. Of particular note, we've highlighted the recent activity, including some direct offsets to our acreage currently being drilled that will clearly enhance our 400,000 net acre position further.

We'll continue to monitor those wells and other Utica activity in Pennsylvania as we go forward. Our best well remains as one of the top four Utica wells in the play. We believe it will hold flat for close to 400 days and the EUR looks to be around 3.25 Bcf per 1,000 foot. Again, essentially all our acreage is HBP'd and we believe the Utica play will play a complementary and important role in the future.

So, a quick operations update. We drilled 9 wells in the past quarter: 7 dry Utica wells in Monroe County, Ohio and two Marcellus wells in Washington County, PA. For one of the Marcellus wells, our team achieved an Appalachian Marcellus drilling record of 7,380 feet drilled in a 24-hour period on our Morris 30B well in Washington County, PA.

In the quarter, drilling efficiency, or days per 1,000-foot of lateral, improved 18% compared to 2016, helping reduce our cost per lateral foot by 11%. In Monroe County, Ohio, the dry Utica wells averaged approximately 9,900 lateral feet while averaging 21.5 drilling days per well, compared to 24 drilling days per well during the fourth quarter of 2016. At the current pace, a single rig could drill 16 dry Utica shale wells per year with 10,000-foot laterals, which is a 14% improvement compared to the fourth quarter of 2016.

Drilling costs for the dry Utica in Monroe County have dropped from $384 per lateral foot in the fourth quarter of 2016 to $351 per lateral foot this quarter, and we expect further improvement in future costs. When you include completion costs, which have increased some due to design changes in proppant loading and proppant type, our Monroe County dry Utica well costs are now around $9 million for a 9,000-foot lateral, which compares to $9.6 million just eight wells ago.

We recently TD-ed the Aikens 5M, our first offset to the Gaut 4H well in Westmoreland County, PA in the deep dry Utica. From a drilling standpoint, we have successfully drilled the Aikens well in a fraction of the time it took to drill the Gaut well. Specifically, it took us 38 days to TD the Aikens well, compared to 167 days to drill the Gaut well.

Previously, we had stated that it would take us five wells to seven wells to get our costs under $15 million. With the improvements seen on the current well and assuming completion operations go as planned, there's a clear path to a sub-$12.5 million deep dry Utica well in the next two wells. Again, this highlights our tremendous rate of change. Results like this are likely to accelerate our shifting focus from the Marcellus to the dry Utica, fast-tracking the Utica development planning process and its infrastructure build-out options.